1. Field of the Invention
The present invention relates generally to a release tool for use in wellbores. More particularly, this invention relates to a release tool for a bottom hole assembly for use with coiled tubing for the purpose of selectively releasing the bottom hole assembly from the coiled tubing. It should be mentioned that throughout this specification, the term bottom hole assembly may include a single downhole tool, or an assembly of multiple downhole tools, by way of example and not limitation, as would be recognized by one of ordinary skill in the art.
2. Description of the Related Art
In the drilling and production of oil and gas wells, it is frequently necessary to isolate one subterranean region from another to prevent the passage of fluids between those regions. Once isolated, these regions or zones may be fraced as required.
Many stimulation techniques for given types of wells are well suited for use with coiled tubing. Generally, it is known to attach a packing device, such as a straddle packer, to coiled tubing and run the packing device downhole until the desired zone is reached. Once positioned, the fracing proppant or sand slurry may be forced into the zone.
However, utilizing coiled tubing to fracture multiple zones can be problematic. The coiled tubing is generally weaker in tensile and compressive strength than its mechanical counterparts. Thus, coiled tubing may be unable to remove a bottom hole assembly that becomes lodged in the casing. Additionally, fracing facilitates the lodging of the bottom hole assembly in the casing as sand tends to accumulate throughout the bottom hole assembly. Thus, a fracing process which (1) requires multiple fracture treatments to be pumped via the coiled tubing and (2) requires that the bottom hole assembly to be repositioned within the multiple zones between treatments is a collision of objectives.
Additionally, the fracing process may be compromised if the proppant is underflushed such that sand slurry remains within the bottom hole assembly and even the coiled tubing. The additional sand can lodge between the bottom hole assembly and the casing. Consequently the coiled tubing may be partially plugged after each treatment.
Further, in the event that the well's casing integrity is breached, it is possible that proppant could be pumped into the well above the zone being treated, leading to the possibility of the coiled tubing being stuck in the hole. Further, the coiled tubing process requires the use of a zonal isolation tool or bottom hole assembly to be fixed to the downhole end of the coiled tubing. The tool may occupy almost the full cross-sectional area of the well casing which increases the risk of the tool or bottom hole assembly being lodged or stuck in the wellbore casing.
Once the bottom hole assembly becomes lodged, due to excess sand from the proppant becoming lodged between the bottom hole assembly and the wellbore casing, the tensile strength of the coiled tubing generally is not strong enough to be able to dislodge the bottom hole assembly. Therefore, the coiled tubing must be severed from the bottom hole assembly and retracted to surface. The bottom hole assembly must then be fished out of the well bore, or drilled or milled out of the well. These procedures increase the time and cost of fracing a zone.
Coiled tubing operations in deeper wells present another problem to operators trying to retrieve the bottom hole assembly and/or coiled tubing from a deep well. It is known to install release tools between the coiled tubing and the bottom hole assembly. Should it be desired to release the bottom hole tool, e.g. because the bottom hole assembly is irreparably lodged in the casing, an upward force may be applied to the coiled tubing to the release tool. The release tool is designed for the application of a known release force—less than the maximum strength of the coiled tubing—upon which the release tool will release the bottom hole assembly, e.g. by shearing pins in the release tool. For shallow wells, the release force can be established at some given value less than the maximum strength of the coiled tubing.
However, in relatively deep wells, the weight of the coiled tubing detracts from the maximum force that may be applied to the release tool. Thus, the release force cannot be known with certainty. In very deep wells, only a relatively small upward force may be applied to the bottom hole assembly, as the weight of the coiled tubing becomes substantial compared to the maximum force the coiled tubing can withstand. Thus, if the release force is set too low, the bottom hole assembly may be mistakenly released while operating in shallow portions of the well. However, if the release force is set high enough so that the bottom hole assembly will not be inadvertently released in the shallow portion of the well, then, when the bottom hole assembly is at deeper portions of the well, the coiled tubing may not have sufficient strength to overcome the weight of the coiled tubing to apply the required release force. Thus, the bottom hole assembly may become stuck in a deep well and the coiled tubing may not be able to retrieve it.
Fracing with coiled tubing can present yet another problem. In other coiled tubing operations, clean fluids are passed through the coiled tubing. Thus, fluid communication is generally maintained between the bottom hole assembly and the surface via the coiled tubing. However, in the fracing process, sand is pumped through the coiled tubing. The sand may become lodged in the coiled tubing, thus preventing fluid communication between the bottom hole assembly and the surface, thus lessening the likelihood that the bottom hole assembly may become dislodged once stuck.
Additionally, current fracturing work done on coiled tubing typically may experience communication between zones on a not-insignificant number of jobs (e.g. approximately 20% of the jobs). Communication between zones occurs due to poor cement behind the casing. Therefore the sand slurry exits in the zone above the zone being treated instead of into the formation. This sand could build up for some time before the operator realizes what has occurred. This sand build up again may lodge the downhole assembly in the well bore.
Straddle packers are known to be comprised of two packing elements mounted on a mandrel. It is known to run these straddle packers into a well using coiled tubing. Typical inflatable straddle packers used in the industry utilize a valve of some type to set the packing elements. However, when used in a fracing procedure, these valves become susceptible to becoming inoperable due to sand build up around the valves.
One type of straddle packer used with coiled tubing is shown in FIG. 1. This prior art straddle packer 1 comprises two rubber packing elements 2 and 3 mounted on a hollow mandrel 4 (not shown). The packing elements 2 and 3 are in constant contact with casing 10 as the straddle packer is moved to isolate zone after zone.
In operation, the straddle packer 1 is run into the wellbore until the packers 2 and 3 straddle the zone to be fraced 30. Proppant is then pumped through the coiled tubing, into the hollow mandrel 4, and out an orifice 5 in the mandrel 4, thus forcing the proppant into the zone to be fraced 30. This type of straddle packer typically can only be utilized with relatively low frac pressures, in lower temperatures, and in wellbores of shallower depth. Wear on the packing elements 2 and 3 is further intensified when a pressure differential exists across the packer thus forcing the packing elements 2 and 3 to rub against the casing 10 all that much harder.
These prior art packers may be used in relatively shallow wells. Shallow wells are capable of maintaining a column of fluid in the annulus between the mandrel and the casing, to surface. The straddle packer when used to frac a zone is susceptible to becoming lodged in the casing by the accumulation of sand used in the fracing process between the annulus between the mandrel 4 and the casing 10. To prevent the tool from getting lodged, it is possible with these prior art packers used in shallow wells to clean out the sand by reverse circulating fluid through the tool. Fluid is pumped down the annulus, and then reversed back up the mandrel. Because the packing elements 2 and 3 only hold pressure in one direction, the fluid can be driven passed the packing element 2 and into the mandrel and back to surface. Again, this is possible in shallow wells as the formation pressure is high enough to support a column of fluid in the annulus to surface. Otherwise, reverse circulation would merely pump the fluid into the formation.
However, when zones to be fraced are not relatively shallow, the formation pressure is not high enough to support a column of fluid in the annulus from the zone to surface. Thus, the reverse circulation of fluid to remove excess sand from the tool is not possible, again increasing the likelihood that the packer may become lodged in the casing 10.
Further, because a column of fluid in the annulus to surface exists, the operator can monitor the pressure of the column and monitor what is transpiring downhole. However, without this column of fluid, such as in deep wells, the operator has no way of monitoring what is transpiring downhole which further increases the chances of the bottom hole assembly becoming lodged.
Thus, it is desirable to provide safeguards to prevent the bottom hole assembly from becoming stuck in the hole, especially when fracing relatively deep zones with coiled tubing. It is further desired to provide a mechanism by which a lodged bottom hole assembly may be “tugged” by the coiled tubing in an effort to dislodge the bottom assembly, without completely releasing the bottom hole assembly.
Another problem with fracing deeper wells with coiled tubing occurs when sand slurry is pumped through the bottom hole assembly at high flow rates. These high flow rates may cause erosion of the casing. Therefore, there is a need to perform the fracing process with coiled tubing which minimizes the erosion on the casing. Thus, a need exists for a bottom hole assembly capable of fracing using coiled tubing which minimizes erosion to the casing and the bottom hole assembly.
Therefore, there is a need for a bottom hole assembly that is capable of performing multiple fractures in deep wells (e.g. 10,000 ft.). Further, there is a need for the bottom hole assembly that may operate while encountering relatively high pressure and temperature, e.g. 10,000 p.s.i. and 150° C., and relatively high flow rates (e.g. 10 barrels/min.).
The present invention is directed to overcoming, or at least reducing the effects of, one or more of the issues set forth above.